This disclosure relates in general to a method and system for analyzing a multiphase mixture flowing in a pipeline. More specifically, but not by way of limitation, embodiments of the present invention provide for withdrawing a sample of the multiphase mixture under isokinetic conditions and flowing the withdrawn sample as a slug-type flow or pseudo slug-type flow, which slug-type flow provides that the phases of the multiphase sample are mostly separated between one essentially dominant (or close to continuous) liquid phase and another essentially dominant gas phase, through one or more measuring, detection, sampling and/or sensing devices. In such embodiments, from the measurements, detection, sampling and/or sensing of one or more of the separated phases in the slug-type flow, flow properties of the multiphase mixture and properties of the phases of the multiphase mixture may be processed. For purposes of this specification, but not by way of limitation, the term phase may be used to describe a gas phase, a liquid phase, a water phase or an oil phase of a multiphase mixture.
In the hydrocarbon industry, it is desirable during the production and/or transport of oil and gas to carry out measurements to determine the properties of a multiphase mixture flowing in a hydrocarbon pipeline where the multiphase flow may consist of a combination of oil, water, gas and/or the like. With regard to the liquid phase of the multiphase mixture, measurement of the properties of the oil and/or water, including among other things the amount of the oil and/or water in a hydrocarbon transporting pipeline is often highly desirable so as to control and regulate hydrocarbon production. For example, it may be important to measure oil being produced by not only an oilfield, but also individual oil wells associated with the oilfield. Measurements may be necessary/desirable in order to determine the water and/or the gas content of the flow being produced from individual oil wells—for production analysis, etc—and/or to allocate production amounts to individual rights owners.
The early detection of water is an important measurement for subsea gas condensate wells where inhibitors may be added to prevent the formation of scale and hydrates in the pipeline downstream of the well head. In such cases, expensive inhibitors may be pumped into the pipeline from the start of hydrocarbon production, the quantity of fluid being determined from reservoir models. To manage the use of the inhibitors, the detection and quantification of the water can result in significant cost savings. Furthermore, in aging oil wells where the gas-volume fraction (GVF) and/or water-cut can be very high (e.g., GVF>95% and/or water-cut>95%), the quantity of oil in the flow line determines the economics of the well.
It is, however, in general, very difficult to obtain measurements when the oil and/or water are flowing simultaneously with gaseous components through the pipeline. The problems associated with taking measurements arise, from among other things, the distribution of the different phases in the pipe—the phases may form different arrangements temporally and spatially—both axially and radially in the pipe. These different arrangements of the multiple phases may create, among other things, nonlinear responses—with the measuring system.
Flow of the multiphase fluid in the pipe may consist, among other flow designations, of a continuous phase—normally, liquid flow—or a discontinuous phase—normally, gas flow. In the continuous phase, the flow may be a continuous oil flow and the flowing oil may contain water droplets. Such flow, being primarily made up of a hydrocarbon substance, may, in general, be marked by low electrical conductance characteristics. In the alternative, the flow may be a continuous water flow with oil droplets distributed in the continuously flowing water. In such situations, the water, which may also have varying degrees of salinity, may provide that the flowing mixture has electrically conductive characteristics that change with time due to water injection or breakthrough, especially in contrast to the oil continuous situation.
With regard to the gaseous components of the multiphase fluid, the gaseous components may be distributed in large volumes or pockets in the multiphase fluid as gas churns or slugs, or may be distributed as small bubbles in the liquid phase, often referred to as bubble flow. Furthermore, under high pressure, such as found downhole, gas in the multiphase fluid may be dissolved in the oil phase. When there are large volumes of gas in the pipeline the gas may govern the multiphase fluid flow and cause the oil and water phase to be pushed back to the pipe wall. In this case, often referred to as annular flow, the oil/water fluid mixture may move at a low velocity along the pipe wall. Additionally annular-mist flow may occur when gas flow dominates the multiphase flow in the pipe (and in mist flow, neither the water phase nor the oil phase is continuous). In such annular-mist flow, gas-carrying droplets of oil or water may move up the center of the pipe at high velocity while the remaining oil or water flows up along the pipe walls at low velocity.
In general, the liquid—which may be formed from multiple liquids mixed together—moves with a common velocity through the pipeline. However, in low flow velocity situations oil and water in the multiphase mixture may become partially or even completely separated. In such situations, the water and oil may travel at different velocities through the pipeline. For a non-horizontal pipe, the lighter oil may move up the pipe faster than the heavier water and causes small water drops to form that may in turn aggregate to form larger drops or slugs that may reach pipe diameter. This type of flow is often referred to as slug flow. The difference in velocity of the oil and water moving through the pipe is often referred to as “slip”. Because gas has a substantially lower density than oil/water or a mixture of the two, a larger slip will occur between the gas and the liquid phases. This pseudo slug or slug flow can be met easily if there is a small diameter and in any type of angle if the capillarity effects are predominant.
These flow properties of the multiphase mixture in the pipeline may make it difficult to analyze the multiphase mixture and/or the properties of the different phases of the multiphase mixture. However, because of the importance of analysis of multiphase mixtures in the hydrocarbon industry, multiphase flow metering and the like has been growing rapidly and with this growth the need for analyzing problematic multiphase mixtures, such as mixtures with a high GVF up to wet gas conditions may be desirable. Measurements/analysis of problematic multiphase flows, such as wet gases and the like have been made possible by accepting some compromises in terms of accuracy on some parameters and the development of unique but expensive sensors. However, even with such compromises and/or use of expensive sensors prior systems may be unable to discriminate with a reasonable accuracy the three phases (gas, oil and water) flowing inside a pipe under conditions such as wet gas flow, high GVF and/or the like. In some cases, only gas/liquid or gas can be measured.
Taking an isokinetic sample of a multiphase mixture flowing through a pipeline may be a very challenging issue. Furthermore, subsequent analysis of the obtained isokinetic sample and/or retrieving a sample of one or more phases of the isokinetic sample may also be troublesome, especially in downhole and/or remote locations and may involve use of complicated and expensive devices, such as phase specific sensors, phase separators, processors for interpolating data obtained from mixed phases and/or the like.